Method and system for generating geophysical data

ABSTRACT

A method of generating geophysical data using at least one source. The method may include the steps of generating a geophysical wavefield with a varying signature using at least one source, wherein the signature is varied in a periodic pattern.

TECHNICAL FIELD

The present invention relates to a method and system for generatinggeophysical data.

BACKGROUND OF THE INVENTION

When generating geophysical data, a geophysical wavefield is typicallygenerated by a source. Examples of known sources are single airguns andairgun arrays, single vibrators and vibrator arrays, waterguns,dynamite, and electric and magnetic sources. Geophysical energy is thenrecorded by a receiver at a location distant from the source. Thegeophysical data recorded by the receiver typically comprises a portionof data from the geophysical wavefield generated by the source, and mayalso comprise geophysical data not originating from the source (e.g.noise, interference and/or geophysical energy from another active orpassive source). It is desirable to know which part(s) of thegeophysical data recorded by the receiver originate from the source. Inthe prior art, attempts have been made to do this by using sources withrandom time dithers or by encoding sources using orthogonal sequences.

In US 2014/0278119, a technique is employed where phases of frequencysweeps are varied from shot to shot.

SUMMARY OF THE INVENTION

However, the present inventors have devised an improved method andsystem for generating geophysical data.

In a first aspect, the invention provides a method of generatinggeophysical data using at least one source, the method comprisinggenerating a geophysical wavefield with a varying signature using atleast one source, wherein the signature is varied in a periodic pattern.

The inventors have found that varying the signature of the generatedgeophysical wavefield in a periodic pattern can greatly improve: theefficiency of geophysical data acquisition, the efficiency ofgeophysical modelling, interference cancellation, noise reduction,deghosting and the accuracy of source-side gradient calculations. Theseimprovements are discussed in greater detail below.

As discussed above, a geophysical wavefield is typically generated by asource. The source can produce a geophysical wavefield at intervals intime, which may be regular intervals in space and/or in time. Thegeneration of the wavefield is typically referred to as a “shot”. Areceiver records geophysical energy, the energy comprising the generatedwavefield. The receiver typically records the geophysical energy in anumber of traces that are sequential in time with respect to each other.The receiver is typically triggered with the source such that thereceiver starts recording each trace when a shot is fired, e.g. when ashot is fired a new trace is recorded. In this way, the receiver recordsa trace for each shot fired. Alternatively, it may be that a geophysicalwavefield is continuously generated by the source and that data iscontinuously recorded by the receiver. In this case, the generatedwavefield and the received data may be divided into time segments. Thesesegments may also be referred to as shots, and may be treatedequivalently to discrete shots.

A plurality of receivers at varying locations are typically used. Thereceiver typically records the geophysical wavefield in the time-spacedomain.

When no periodic signature pattern is used, the inventors have observedthat if the recorded geophysical data is transformed into another domain(such as frequency-wavenumber), substantially all of the data is locatedin only a portion of the space of that domain, i.e. there are portionsof the space of that domain where substantially no data exists. Forinstance, when no periodic signature pattern is used and the recordeddata is transformed into the frequency-wavenumber domain, all of thedata fall within a signal cone centred around wavenumber k=0. At alllocations in the domain outside of the signal cone and up to the Nyquistwavenumber k_(N), there is no geophysical data. This is described inmore detail below with reference to FIG. 1.

The inventors have realised that if it were possible to move at leastsome of the data from a particular source recorded at a receiver to adifferent location in the other domain, then more of the space in theother domain could be used.

The inventors have also realised that this could allow for the use ofmultiple simultaneous sources, for example, with the data from eachsource having its own location in the other domain. Since data from eachsource could have its own location in the other domain, it is possibleto know which data came from which source, and it is possible toseparate the data from each source. This allows for greater density ofdata sampling, and hence greater efficiency. Similarly, the inventorshave realised that when data from each source has its own location inthe other domain, then the recorded data can be directly filtered in thedomain in which it is recorded (e.g. time-space or frequency-spacedomain) to extract or reject data from each source.

The inventors also realised that similar principles could also be usedto move the data signal in the other domain to a location away from datarecorded from noise and/or interference, or equivalently move noiseand/or interference away from the data signal. The data from the noiseand/or interference could then be used or removed. Equivalently, thedata could be filtered in the first domain (i.e. the domain in which itis recorded) to remove the noise and/or interference.

There may also be numerous other uses and benefits associated with beingable to move data in the other domain.

The inventors discovered that by using a periodic varying signature onthe generated geophysical wavefield, the data recorded from thatwavefield could, when transformed into an appropriate domain, be shiftedfrom its expected location. It is this principle that the inventorsdiscovered and from which the numerous advantages and applicationsdiscussed above, and in more detail below, arise.

Thus, the periodic pattern may be such that, when the geophysicalwavefield is recorded and the recorded geophysical data is transformedinto another appropriate domain, at least some of the recordedgeophysical data is shifted to a location that is different to thelocation where the at least some of the geophysical data would have beenhad the varying signature not been used. The location where the at leastsome of the geophysical data would have been had the varying signaturenot been used may be the location where the at least some of thegeophysical data would have been had no varying signature been used.When using a seismic wavefield, and when transforming into thefrequency-wavenumber domain, this location may be a signal cone centredaround k=0.

The method uses a deterministic variation of the signature of the sourcesuch that, when the generated geophysical wavefield is recorded andtransformed into an appropriate domain, the location of at least part ofthe recorded geophysical data is shifted in that domain. The signaturemay be varied in a repeated pattern. The signature may have adeterministic periodic variation.

The periodic variation in signature may be a periodic variation of thesignature of subsequent generated wavefields (e.g. from shot to shot).Thus, the signature of each generated wavefield may not vary withrespect to itself (i.e. each generated wavefield may only have onesignature), but the signature of each wavefield may vary with respect tothe signatures of other generated wavefields generated at differentlocations and/or times.

An appropriate domain is any domain that shows a shift in the locationof the geophysical data. For instance, the geophysical data may berecorded in a time-space domain. The other domain may be afrequency-wavenumber domain or a tau-p domain.

The shift may be a shift along the axis in the transformed domain.

The method may comprise recording geophysical energy to producegeophysical data using at least one receiver, the geophysical energycomprising the propagating geophysical wavefield generated at the atleast one source; and transforming the geophysical data into anotherdomain. The other domain may be a domain such that at least some of thegeophysical data is shifted to a location that is different to thelocation in the other domain where the at least some of the geophysicaldata would have been had the varying signature not been used. Here, theat least some of the recorded geophysical data may be all or part of therecorded geophysical data originating from the propagating geophysicalwavefield generated by the source.

The receiver may record the geophysical energy in the space-time domain.

The transform may be any transform capable of transforming the data intothe appropriate domain. The transform may be a spatial transform. Thetransform may be a Fourier transform. The transform may be a radontransform. The transform may be a tau-p transform.

When in the appropriate domain, the shift in the data location due tothe periodic signature pattern may be a shift in a dimension that is thetransform of a spatial dimension. When in the frequency-wavenumberdomain, the shift may be by k_(N)/n, e.g. k_(N), k_(N)/2, k_(N)/3, etc.,where k_(N) is the Nyquist wavenumber.

The at least one receiver may be at a distance from the at least onesource.

There may be a plurality of receivers spaced in a generally lineardirection.

The at least one source may be moved between different locations betweengenerating subsequent shots. The source may be moved at a constantvelocity, and the shots may be fired at constant time intervals, so asto form uniform distance spacing between shot locations. However, it maybe that, due to environmental factors for instance (such as winds, seacurrents, etc.), the source may not be moved at a constant velocity. Inthis case, the wavefields may still be generated at constant distanceseparation by varying the time accordingly between subsequent shots. Thesource may be moved linearly, so that shot locations form a straightline. The source may be moved such that a substantially uniform grid ofshot locations is formed.

The method may comprise isolating the geophysical data originating fromthe generated geophysical wavefield from the source from any othergeophysical data that may be present in the other domain. This may bedone by, for instance, muting the other geophysical data. The othergeophysical data may be from other sources, or interference, or noise.The isolated geophysical data originating from the generated geophysicalwavefield can then be transformed back into the domain in which it wasrecoded (e.g. the time-space domain). Thus, a geophysical data setcorresponding to the (or each) source may be obtained. This data set canbe conditioned (e.g. mathematically) to remove the variation imposed onit by the varying signature. For example, the polarity of appropriatetraces can be changed, or the time of different triggers can be changed.This conditioning results in a geophysical data set corresponding to theat least one source that is in a conventional form (i.e. as if it hasbeen generated without any varying source signature) but that has beensuccessfully separated/isolated from other geophysical energy signalsthat may be present.

The method may comprise recording geophysical energy to producegeophysical data using at least one receiver, the geophysical energycomprising the propagating geophysical wavefield generated at the atleast one source; and isolating the geophysical data originating fromthe propagating geophysical wavefield generated at the at least onesource from any other geophysical data that may be present in the otherdomain.

The isolating step may comprise filtering the recorded data. Thisfiltering may occur in the domain in which the geophysical energy isrecorded. This filtering may occur in the domain in the space-timedomain or the space-frequency domain. Thus, there may be no need totransform the recorded data into a transformed domain. The filterapplied may be a spatial filter, e.g. a space-time filter or aspace-frequency filter. The filter may be chosen/created/modelled basedon the knowledge that the varying signature will create a shift in thetransformed domain. For example, the skilled person may appreciate thatif data is going to be shifted in the wavenumber space, then a spatialfilter may be applied in spatial space so as to isolate a portion of thedata that would be shifted if all the data were transformed intowavenumber space. The filter can be designed such that it has theequivalent data isolation/extraction/rejection properties as thetransforming, isolating and re-transforming steps discussed above (i.e.it may isolate the same data as the other isolation method, but withoutrequiring the step of transforming the data).

For instance, it may be possible to design a filter, which may include atransform, that effectively extracts the desired signal (e.g. the signalthat would be shifted in the transformed domain). The data in therecorded domain can then be convolved with this filter to output thesought-after data in the recorded domain. The key point is that thefiltering of the data in the recorded domain may equally well achieveisolation of the desired data if a suitable filter is used. Such afilter may be designed with an understanding of the theory and with aknowledge of the varying source signature. Thus, the isolation can beachieved by convolving space-time or space-frequency data with aspace-time or space-frequency filter. The filter may be designed so thatit extracts or rejects portion of the transformed domain space (e.g. thefrequency-wavenumber space). Such a filter may not be limited tospace-time or space-frequency space; rather it may in any domain inwhich data is recorded.

This isolated data may also be conditioned.

Conditioning may occur in the domain in which the geophysical data wasrecorded. Conditioning may occur in the space-time or space-frequencydomain.

The periodic pattern may be such that, after transforming the recordedgeophysical data into the other domain, a first portion of the recordedgeophysical data is shifted to a location that is different to thelocation in the other domain where the first portion of the geophysicaldata would have been had the varying signature not been used (i.e. ashifted location), and a second portion of the recorded geophysical datais at a location that is the same as the location in the other domainwhere the second portion of the geophysical data would have been had thevarying signature not been used (i.e. a non-shifted location). Looked atanother way, the periodic pattern may be such that, after transformingthe recorded geophysical data into another appropriate domain, a firstportion of the recorded geophysical data originating from thepropagating geophysical wavefield generated by the at least one sourcewould be shifted relative to a second portion of the recordedgeophysical data originating from the propagating geophysical wavefieldgenerated by the at least one source. This is different to US2014/0278119 where all of the data originating from one source isshifted.

The second portion may be the remaining portion of the recorded data,i.e. the recorded data may consist of the first and the second portions.Alternatively, there may be other portions present shifted relative toboth the first and the second portions.

Thus, it should be appreciated that the geophysical data originatingfrom the generated geophysical wavefield may be split into two (or more)different portions that are shifted to different locations in thetransformed domain. Some of the data originating from the source (thesecond portion) is found at one location and some of the dataoriginating from the source (the first portion) is found at locationshifted relative to the second portion. Thus, it can be appreciated thatboth the first and the second portions are incomplete relative to thefull data signal that would have been received at one location had novarying signature been used. In the present application, themultiplicative effect of these missing portions of the data are referredto as “ghosts” in each portion of the data. These “ghosts” may beconsidered to be functions which, when multiplied with the full datasignal produce the differently shifted portions of the full data signal.Each data portion has an associated “ghost” and the “ghost” associatedwith each data portion may be different to the ghost(s) associated withthe other portion(s), i.e. the “ghost” associated with the first portion(the “first ghost”) is generally different to the “ghost” associatedwith the second portion (the “second ghost”). However, the sum of theall the ghosts should essentially equal 1 (one) as no energy/data islost or created when partitioning the data into the first and secondportions, i.e. substantially no data is lost or created, it is just thatsome has been shifted relative to the remainder. Thus, looked at anotherway, the first portion of the data may be equal to the full datamultiplied by the first “ghost” (shifted to the first location), and thesecond portion of the data may be equal to the full data multiplied bythe second “ghost”. The first ghost plus the second ghost may equal 1(one), where the full data is split into only two portions.

The inventors have devised a method of reconstructing thispartially-shifted data so as to obtain fully-shifted data. The inventorshave also devised a method of removing the second portion (e.g.non-shifted portion) of the data. Once these two steps are performed, itshould be appreciated that the data will effectively appear to have beenfully shifted. These two steps may be performednumerically/mathematically. The details of these steps are set outbelow.

When the data has undergone a partial shift due to a varying periodicsource signature, the shifted data may be clearly seen and identified inthe transformed domain (because it is shifted away from the remainder ofthe data). However, the non-shifted portion of the data originating fromthe generated wavefield may not be as clearly identified because theremay be data from other sources at the non-shifted location. Thus, onlythe shifted portion can be reliably identified.

However, since the shifted portion is known, the shifted portion can be“deghosted”. As mentioned above, the term “ghost” refers to themultiplicative effect of the missing parts of the data in the shiftedportion (the missing portion being related to the non-shifted portion).Hence, “deghosting” refers to removing the ghosts by filling in themissing portion of the shifted data portion at the shifted location,i.e. effectively removing the missing portion of the data at the shiftedlocation.

In contrast, since US 2014/0278119 shifts all of the data from onesource, there is no partial shift of the data in US 2014/0278119. Thepresent inventors have devised a method that allows all the data fromone source to be shifted, even if the source signature variation is onlysuch that only a first portion of the data from the source to beshifted: the second (or remaining) portion is shifted or accounted forby calculating it from the first portion. This method in turn allows forthe use of much more primitive signature variations (such as ones thatcause only partial shifting of the data, such as time dither, amplitudevariations), rather than the much more precise phase variations requiredby US 2014/0278119. Using more primitive signature variations isadvantageous as they are easier to control and allows for the use ofsimpler cheaper more conventional sources, such as air guns.Essentially, the fact the inventors have devised a method that works fora signature variation that only shifts part of the date from a sourceleads to a much simpler, more robust and cheaper method of acquiringseismic data, in comparison to US 2014/0278119.

The theory behind the method disclosed in US 2014/0278119 is awell-known shift property of Fourier Transforms. This shift propertyrequires an exact and specific modulation of the source. The presentinventors have advanced from US 2014/0278119 in that they have devised amethod where there is no need to have such exact and specific modulationfunctions as prescribed by the shift property. For the first time, thepresent inventors have devised a new method (based on a new equationthat the inventors have derived) that allows for (at least) partialshifting of the data even with less exact and specific modulation of thesource signature. Any non-shifted data can be found from thenewly-derived theory and then shifted to effectively fully-shift thedata, but without requiring the exact and specific source signaturemodulation. This allows cheaper, simpler, more conventional marinesources (such as air guns) to enjoy the same benefits as the marinevibroseis sources described in US 2014/0278119 (e.g. for simultaneoussource acquisition). The present method may comprise the steps of:identifying the first portion; and processing the data to calculate afull data signal at the shifted location of the first portion using theidentified first portion. US 2014/0278119 does not include such a stepsince the data from a given source is necessarily always fully shifted.The “full data signal” here is intended to mean the data that would havebeen shifted to the shifted location had the signature been varied insuch a pattern to achieve this, i.e. that substantially all the dataoriginating from the generated wavefield is effectively shifted to theshifted location of the first portion (by a combination of actuallyshifting the data and mathematically/numerically shifting the data).

The calculation of the full data signal at the shifted location of thefirst portion using the identified first portion (i.e. the “deghosting”of the first portion) may be achieved by deconvolution of the firstportion. The deconvolution is achieved by knowing the expected shift ofthe first portion (e.g. the expected shifted portion and the expectednon-shifted portion) for a given source signature pattern, which may bederived from theory. The first portion can be deconvolved to find thefull data signal at the first shifted location using a function/equationderived from theory. The first portion can be deconvolved with a firstghost, the first ghost having been derived from theory (since firstportion is equal to the first ghost multiplied by the full data, if thefirst portion is known and the first ghost can derived from theory, thefull data can be recovered by deconvolution).

Alternatively to deconvolution, it is also possible to calculate thesecond portion, since the first portion is known (since it has beenidentified). This can be calculated by knowing the expected data shiftfor a given source signature pattern. This can be derived from theory.Once the second portion is calculated, it can be added to the firstportion in the appropriate first shifted location. This also achievesthe desired deghosting.

Deconvolution is preferable since it is achieved in one step and doesnot require the explicit step of calculating the non-shifted portion ofthe data. However, both these techniques achieve the same result of“deghosting” the first portion of the data.

Once the first portion has been identified, the method may also compriseprocessing the data to remove the second portion of the data using theidentified first portion.

This may be achieved by effectively calculating the second portion fromthe first portion. This may be done by calculating the full data signalusing the first portion (i.e. “deghosting” the first portion, asdiscussed above) and then calculating the second portion from the fulldata (i.e. “reghosting” the full data, using a ghost functioncorresponding to the second portion). This operation may be thought ofas “reghosting” the “deghosted” first portion so that the “reghosted anddeghosted” first portion has data that only corresponds to that of thesecond portion. This may be achieved by convolution of the full datasignal at the first shifted location. The convolution is achieved byknowing the expected shift of the first portion relative to the secondportion (e.g. the expected shifted portion and the expected non-shiftedportion) for a given source signature pattern, which may be derived fromtheory. The full data (found by deghosting the first portion) can beconvolved with a second ghost, the second ghost having been derived fromtheory (since the second portion is equal to the second ghost multipliedby the full data, if the full data is known and the second ghost canderived from theory, the second portion can be calculated byconvolution).

Alternatively to convolution, it is also possible to calculate thesecond portion, since the shifted portion is known (since it has beenidentified). This can be calculated by knowing the expected shift forthe first portion for a given source signature pattern. This can bederived from theory.

Regardless of whether the calculated second portion is found by“reghosting” the “deghosted” first portion, or by direct calculationfrom the first portion, once the second portion is calculated it can besubtracted from the recorded data at the location of the second portion(which may be the non-shifted location).

In a particularly preferred embodiment, the numerical/mathematicalcompletion of the full data signal at the first shifted location and theremoval of the second portion of the data from the second location maybe carried out simultaneously, or in a single step, for example by usinga common filter.

The net effect of deghosting and reghosting is that the second portion(the non-shifted portion) of the data may appear to have effectivelybeen shifted to the shifted location. This may be achieved by a dataprocessing technique, as discussed above.

Alternatively the net effect of deghosting and/or reghosting may beachieved by designing an appropriate filter. Using such a filter (asdiscussed above) may remove the need to transform the data into theother domain.

The periodic varying signature can be modelled as a mathematicalfunction that modulates the generated geophysical wavefield and therecorded geophysical data.

For instance, when the signature is varied using time dither (see below)such that the trigger time of every second generated wavefield from thesource is delayed, or advanced, by a time dither T the modulatingfunction may be:

$\begin{matrix}{{g(n)} = {{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack} + {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}\left( {- 1} \right)^{n}}}} & (1)\end{matrix}$

where n is trace number. If the modulating function g(n) is applied toconventional (i.e. with no time dither) data f(n), and the Fouriertransform of the product is taken, the result is

$\begin{matrix}{{{\mathcal{F}\left( {{f(n)}{g(n)}} \right)} = {{{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack}{F\left( e^{ik} \right)}} + {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}{F\left( e^{i{({k\;\pi})}} \right)}}}},} & (2)\end{matrix}$

where F(e^(ik))=F(f(n)) and F(e^(i(k−π))=F(f(n)(−1)^(n)).

From equation 2, the F(e^(ik)) term is centred around k=0 and is thenon-shifted portion. The F(e^(i(k−π))) term is centred around k=k_(N)and is the shifted portion. As mentioned above, the shifted portion canbe identified and measured from the recorded and transformed data, butit may be difficult to measure the non-shifted portion. However, themissing parts of the shifted data can be filled in (i.e. the “ghosts” inthe shifted portion can be “deghosted”) using Equation 2 (or any othermodel for a different source signature pattern) by deconvolution. Usingthe equation 2 as an example, the full data can be calculated using thefirst (shifted) portion of the data because

${{first}\mspace{14mu}{portion}} = {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}*{full}\mspace{14mu}{{data}.}}$

Alternatively, the non-shifted portion can effectively be calculatedusing Equation 2 (or any other model for a different source signaturepattern) because the shifted portion is known. Once the non-shiftedportion has been calculated, it can be added to the shifted portion ofthe data at the shifted location. These data would effectively look likefully shifted data. Further, the calculated non-shifted portion can bedeleted from the recorded data at the non-shifted location to remove thenon-shifted portion in the measured data, e.g. by “reghosting” the“deghosted” shifted portion so as to find only the data corresponding tothe “ghosts” in the first portion, and subtracting the “reghosteddeghosted” shifted data from the non-shifted data. Using the equation 2as an example, the second (non-shifted) portion can be calculated usingthe full data (found by “deghosting” the first portion)

${{second}\mspace{14mu}{portion}} = {{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack}*{full}\mspace{14mu}{{data}.}}$

The shifted portion may be deghosted using mathematical modelling (e.g.using equation 2), where the shifted portion and the total data is knownfrom the transformed data.

After deghosting and/or reghosting, the (fully) shifted data can beisolated and processed as discussed above.

However, it may not be necessary to deghost/reghost the data to produceuseful data. For instance, the shifted portion alone can be isolated bymuting the remaining data (which includes the non-shifted portion), orthe shifted portion alone can be muted leaving the non-shifted portionand any other recorded data from other energy sources. It may be thatonly the shifted data is isolated or removed. (As discussed below, someof the data may be shifted and some of the data may not be shifted). If,for example, only the shifted data (i.e. non-deghosted shifted data) isremoved, then partial residual shot noise attenuation can be achieved.

The signature of the source may be any feature of the source that, whenperiodically varied (e.g., from shot to shot), may cause the locationshift of at least some of the data when transformed into an appropriatedomain. For example, the time at which the wavefield is generated by thesource can be varied, and/or the polarity of the source and/or the phaseof the source and/or the amplitude of the source can be varied. Theseare four examples of the signature of the source. There may also beother features of the source that can be varied periodically so as tocase the data shift. For instance, when the source is an airgun array,the following parameters influence the signature of the source: numberof guns, geometry of guns, depth, pressure, timing, water velocity, seatemperature and sea surface conditions. Further, signatures of vibratorsources and vibrator arrays may depend on number of vibrators, geometry,sweep, sequence, timing/delay/advance and polarity.

As mentioned above, the signature may be varied using time dither.Typically a source generates wavefields at regularly spaced times or atregularly spaced locations as the source is moved. It is also known touse random dithers in which the times that subsequent shots are firedare dithered randomly. However, the present method may use a periodictime dither pattern (i.e. when time dither is used to implement theinvention, it is periodic). This may be considered to be a discrete timedither approach.

A time dither is where the generated wavefields, which would typicallybe generated at a certain time, is instead triggered at a slightlydelayed, or advanced, time. For instance, without time dither, thegenerated wavefield may be generated when a moving source reaches acertain spatial location (known, for example, by GPS). When the sourcereaches the location, the source triggers and a wavefield is generated.A time dither may be where the source does not trigger as soon as thesource reaches the given location; instead the source may trigger at aslightly delayed time (or it may be triggered at a slightly advancedtime just before the source reaches the given location). Alternatively,the source, without time dither, may generate wavefields at equallyspaced times. A time dither in this case may be where the source insteadis triggered at a slightly delayed, or advanced, time in comparison toits expected trigger time. The time dither may be considered to be adeterministic delay, or advance, of the source trigger time incomparison to an expected trigger time.

As an example of periodic time dither, every second source shot could betriggered with a constant delay of time T. Of course, other time ditherpatterns may be used, e.g. every third generated wavefield, fourthgenerated wavefield, n^(th) generated wavefield could be dithered ordifferent generated wavefields could be dithered by different amounts.Alternatively, the pattern may be two consecutive shots without delay,then two consecutive shots delayed by a constant time shift, the twoconsecutive shots without time shift, etc. All that is necessary is thatthe dither pattern is periodic such that it produces a shift in the datawhen it is transformed into an appropriate domain.

The dither time T may be of any length, but may preferably be up to 10ms, 20 ms, 30 ms, 40 ms, 50 ms, 100 ms or 200 ms, preferably between 10ms and 40 ms, between 40 ms and 200 ms, preferably greater than 200 ms.

The time dither T is preferably substantially less than the time takento move the source between adjacent firing locations. This means thatthe selected firing location is not greatly moved by the delay time T.The dither time T is preferably substantially less than the time betweengenerated wavefields, which may typically be up to 5 s, 10 s or 20 s.

Preferably, the dither time T is selected so as to avoid being

$\frac{n}{2}$of the period of the (dominant) frequency of the geophysical wavefield.This is to be avoided, if possible, because when dither time T is

$\frac{n}{2}$of the period of the (dominate) frequency of the geophysical wavefield,then one of the terms in equation 2 will be zero, which can produceissues during data processing (e.g. dividing by zero causessingularities).

As mentioned above, filters in the recording domain (e.g. space-time)can be designed to predict, extract, or reject components of the datathat we are interested in (e.g. from the one or more sources).

As mentioned above, using time dither may lead to only partial shiftingof the data in the transformed domain. The origin of this partialshifting is now explained further.

Taking the case where every second trace has a time dither T compared toneighbouring traces, the modulating function that describes how the timedither alters conventional (i.e. non-dithered) data f(n) is:

$\begin{matrix}{{g(n)} = {{\frac{1}{2}\left( {- 1} \right)^{n}} + \frac{1}{2} - {\frac{1}{2}\left( {- 1} \right)^{n}e^{i\;\omega\; T}} + {\frac{1}{2}{e^{i\;\omega\; T}.}}}} & (3)\end{matrix}$

Equation (3) can be written more compactly as, the sum of two modulatingfunctions (one of which is a constant with respect to n). This is thesame as equation 1:

$\begin{matrix}{{g(n)} = {{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack} + {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}{\left( {- 1} \right)^{n}.}}}} & (4)\end{matrix}$

Finally, we apply the modulating function g(n) to the conventional dataf(n) and take the Fourier transform and obtain the result:

$\begin{matrix}{{\mathcal{F}\left( {{f(n)}{g_{2}(n)}} \right)} = {{{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack}{F\left( e^{ik} \right)}} + {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}{{F\left( e^{i{({k\; - \pi})}} \right)}.}}}} & (5)\end{matrix}$

Equation 5 shows that the geophysical data will be mapped in two places.Part of the data will remain at the signal cone centred around k=0 andanother part of the data will be mapped to a signal cone centred aroundthe Nyquist wavenumber k_(N).

As explained above, by only knowing one of these parts of the data wecan predict the other using equation 5 to “deghost” or “reghost” thedata. Of course, any other equivalent equation for another time ditherpattern can be used for this step.

When time dither is used, the remainder of the signature of thegenerated wavefields may be identical.

Whilst the time dither method has been explained in terms of a delayedtime shift, it should be understood that this is exactly equivalent togenerating wavefields early by the same time shift (depending on whichwavefields you consider as being the un-shifted wavefields).

Time dither may be the preferred signature variation because it can beperformed using conventional sources (e.g. an airgun), i.e. there is noneed for any special or adapted source.

Additionally or alternatively, the signature may be varied by varyingthe polarity of the generated geophysical wavefield. The polarity may bevaried from geophysical wavefield to geophysical wavefield such thatpolarities alternate in sequence. This is particularly useful when usingthe present method in modelling geophysical wave propagation, fullwaveform inversion, or reverse time migration.

As an illustrative example, the alternating sequence may be such thatevery second generated wavefield has opposite polarity (e.g. +1, −1, +1,−1 etc.).

In this case, a recorded common receiver gather will have every secondtrace with flipped polarity. This may be represented as the followingmodulating function having been applied to a conventional data set f(n)where all traces had the same source signature:g(n)=(−1)^(n).  (6)

Equation 6 can also be written asg(n)=e ^(iπn).  (7)

By applying the function g(n) in equation 7 as a modulating function todata f(n) before taking a (normalized) discrete Fourier transform:

(f(n))=F(e ^(ik)),we obtain

(f(n)g ₁(n))=

(f(n)e ^(iπn))=F(e ^(i(k−π))),  (8)

Equation 8 shows that modulating a function with equation 6 results in awavenumber shift by the Nyquist wavenumber k_(N).

Thus, it can be appreciated that when alternating polarity flips areused, the recorded data, once transformed into an appropriate domain,will be shifted away from the location where the data would have beenhad no varying signature been used.

As another example, a second generated geophysical wavefield may havethe same polarity as a first generated geophysical wavefield, a thirdgenerated geophysical wavefield may have opposite polarity to the secondgenerated geophysical wavefield, a fourth generated geophysicalwavefield may have the same polarity as the third generated geophysicalwavefield, a fifth generated geophysical wavefield may have oppositepolarity to the fourth generated geophysical wavefield, a sixthgenerated geophysical wavefield may have the same polarity as the fifthgenerated geophysical wavefield, (i.e. +1, +1, −1, −1, +1, +1, −1, −1).This may be considered as alternating polarity of pairs of geophysicalwavefields. Such a sequence leads to shift in the data of ±k_(N)/2.

Any other sequence can be used. All that is necessary is that thepolarity pattern is periodic and produces a shift in the data when it istransformed into an appropriate domain.

When the polarity is varied, the remainder of the signature of thegenerated wavefields may be substantially identical.

Polarity variation and time dither may both be used together. Theremainder of the signature may be substantially identical.

Varying the polarity of the source may be achieved in a number of ways.

More generally, in comparison with the specific time dither example ofequations 3-5 and the specific polarity example of equations 6-8, thefollowing general mathematical description is applicable for aperiodically-varying source signature. The following mathematicaldescription is applicable when a source is excited with the samesignature at all even source location numbers and when, at all oddsource location numbers, the source signatures are also identical toeach other but differ from the source signature at the even sourcelocation numbers such that the source signature at the odd sourcelocation numbers is a scaled or filtered version of the source signatureat even source location numbers. Let this convolution filter be denotedby a(t), with frequency-domain transform A(ω). Analysed in the frequencydomain, a receiver gather (e.g. one receiver station measuring theresponse from a sequence of sources) recorded in this way, can beconstructed from the following modulating function g(n) applied to aconventionally sampled data set:

$\begin{matrix}{{g(n)} = {{\frac{1}{2}\left( {1 + \left( {- 1} \right)^{n}} \right)} + {\frac{1}{2}{A(\omega)}\left( {1 - \left( {- 1} \right)^{n}} \right)}}} & (9)\end{matrix}$

which can also be written as

$\begin{matrix}{{g(n\;)} = {{\frac{1}{2}\left( {1 + e^{i\;\pi\; n}} \right)} + {\frac{1}{2}{A(\omega)}\left( {1 - e^{i\;\pi\; n}} \right)}}} & (10)\end{matrix}$

Equation 10 is a more general formulation of equation 1 and equation 6.In equation 1 (e.g. for period time dither, T), A(ω)=e^(iωT). Inequation 6 (e.g. for periodic polarity changes), A(ω)=−1. Other possiblesignature variations are also possible and can be represented as A(ω)=1,A(ω)=0, A(ω)=1+e^(iωT).

By applying (e.g. record by record temporal convolution) the functiong(n) in equation 9 as a modulating function to data f(n) before taking a(normalized) discrete Fourier transform in space (N uniformly spacesource points over n):

${F(k)} = {\frac{1}{N}{\sum\limits_{n = 0}^{N - 1}{{f(n)}e^{{- i}\; 2\;\pi\;{{kn}/N}}}}}$

we obtain

$\begin{matrix}\begin{matrix}{{H(k)} = {\frac{1}{N}{\sum\limits_{n = 0}^{N - 1}{{f(n)}{g(n)}e^{{- i}\; 2\;\pi\;{{kn}/N}}}}}} \\{= {{\frac{1 + {A(\omega)}}{2}{F(k)}} + {\frac{1 - {A(\omega)}}{2}{F\left( {k - k_{N}} \right)}}}}\end{matrix} & (11)\end{matrix}$

which follows from a standard Fourier transform result.

Equation 11 shows that the recorded data f will be mapped into twoplaces in the spectral domain as illustrated in FIG. 2. Part of the datawill remain at the signal cone centred around k=0 and part of the datawill be mapped to a signal cone centred around k=k_(N).

The amount of data that is shifted from k=0 to k=k_(N) and the amount ofdata that remains at k=0, depends on the function A(ω).

The fraction of the data that is shifted from k=0 to k=k_(N) is given by

$H_{-} = {\frac{1 - {A(\omega)}}{2}.}$The fraction of the data that remains at k=0 is given by

$H_{+} = {\frac{1 + {A(\omega)}}{2}.}$

When A(ω)=1. H⁻=0 and H₊=1. Thus, all the data remains at k=0.

When A(ω)=−1. H⁻=1 and H₊=0. Thus, all the data is shifted to k=k_(N).

When A(ω)=0. H⁻=½ and H₊=½. Thus, half the data is shifted to k=k_(N)and half of the data remains at k=0.

When A(ω)=½. H⁻=¼ and H₊=¾. Thus, one quarter of the data is shifted tok=k_(N) and three quarters of the data remains at k=0.

When A(ω)=e^(iωT). H⁻=(1−e^(iωT))/2 and H₊=(1+e^(iωT))/2. Thus, afrequency-dependent portion of the data is shifted to k=k_(N) and theremaining portion remains at k=0. For instance, when

${\omega = \frac{2\;\pi\; n}{T}},{H_{-} = {{0\mspace{14mu}{and}\mspace{14mu} H_{-}} = 1}},$so none of the data with a frequency of

$\omega = \frac{2\;\pi\; n}{T}$is shifted to k=k_(N) and it all remains at k=0; and when ω=π(2n+1)/T,H⁻=1 and H⁻=0, so all of the data with a frequency of ω=π(2n+1)/T isshifted to k=k_(N) and none remains at k=0.

When A(ω)=1+e^(iωT). H⁻=^(iωT)/2 and H₊=1+e^(iωT)/2. Thus, afrequency-dependent portion of the data is shifted to k=k_(N) and theremaining portion remains at k=0.

Importantly, and as has been discussed in detail above, by knowing orobserving one of the portions of the data (e.g. the shifted portion, orthe none-shifted portion), it is possible to predict the other portionof the data. In the present method, it is therefore not necessary tofully shift the data, which means simpler, more primitive sourcesignature variations (such as time dither or amplitude changes) can beused. In turn, this allows the present invention to be performed usingsimple sources, such as air guns. This is different to US 2014/278119where it is necessary to use a very strict phase variation in order tofully-shift the data from a source. The strict phase variation can onlybe performed using marine vibrator sources.

Returning to the present method, a marine vibroseis source may be used.The marine vibroseis source enables a high degree of control of thesource signature and emitting a signal with opposite polarity is fairlystraightforward. However, they are expensive and time-consuming to use.It may therefore be preferable to use a simpler source, which (incontrast to US 2014/0278119) the present method allows the use of.

A water gun may be used. A water gun source has a main peak that hasnegative polarity instead of positive polarity and could therefore beused in combination with an airgun source (which has a main peak that ispositive) to acquire the desired data.

Air gun sources may be used. The air gun sources may be located relativeto each other such that they effectively produce signatures that aresubstantially opposite in polarity.

It should be noted that, in modelling, reverse time migration, inversionor imaging applications, it is not necessary to have any particularapparatus that can achieve the desired source signature variation.Rather, the source can simply be chosen and modelled synthetically, soit is irrelevant how the signature could be varied in the “real life”scenario.

The method may comprise varying the signature of the at least one sourcesuch that, once geophysical energy comprising the generated geophysicalwavefield and another signal is recorded and the recorded geophysicaldata is transformed into another appropriate domain, the recordedgeophysical data originating from the generated geophysical wavefieldwill be shifted away from recorded geophysical data originating from theother signal. The other signal may be noise, interference, or one ormore other sources.

At least two sources may be used to simultaneously generate geophysicalwavefields. The first source may have a varying signature. The secondsource may have no varying signature, or may have a different varyingsignature. Thus, once the geophysical energy is recorded and transformedinto another appropriate domain, the geophysical data from the firstsource will be shifted away from the geophysical data of the secondsource.

There may be any other number of sources, each with a differentsignature such that all data from all sources are separated from oneanother after an appropriate transform.

In the prior art, attempts have been made to record seismic data usingmultiple simultaneous sources by using random time dithers or encodingsources using orthogonal sequences.

The present method provides an improved method for using two (or more)simultaneous sources because the recorded data from each source can beshifted in the transformed domain, and so the data from each source canbe separated, and therefore identified and isolated, from the recordeddata from the other source(s).

This is a particularly important use of the present invention, as usingmultiple sources can decrease the amount of computation required duringmodelling (modelling can be very computationally heavy, so this is animportant consideration). For instance if two sources are usedsimultaneously in modelling, computation required to obtain the sameamount of data can be a half, and if three sources are usedsimultaneously, computation can be reduced to a third. Theoretically, ifn sources are used simultaneously, the computation required to obtainthe same amount of data in comparison to a single source is 1/n.

Similarly, using multiple sources can increase the rate at whichgeophysical data is acquired during acquisition. For instance, if twosources are used simultaneously, data can be acquired at approximatelytwice the rate in comparison to a single source, and if three sourcesare used simultaneously data can be acquired at approximately threetimes the rate. Theoretically, if n sources are used simultaneously,data can be acquired n times faster.

Thus, when multiple simultaneous sources are used, the present methodcan allow the data from at least one of the sources to be identified inthe data recorded by the receiver. This can be useful in many differenttechniques. For instance, when using a source array (which typicallycomprises a plurality of smaller source elements spread over an area),it can be desirable to interpolate data to positions between locationsat which shots are fired. Knowing which recorded wavefield came fromwhich source can greatly ease this calculation.

Further, using multiple sources can allow for a wider range offrequencies to be used.

For instance, a low frequency source and a high frequency source couldbe used simultaneously, and/or airgun source(s) and vibrator(s) could beused simultaneously. Without the present method, at intermediateoverlapping frequencies, the recorded data from these two sources wouldinterfere. However, the present method can be used to separate therecorded data from such sources. Thus, the method may be used for broadband seismic acquisition or modelling. In broadband acquisition ormodelling, one or more low-frequency generating source(s) (such as theseismic equivalent of a “subwoofer”) may be used simultaneously with aconventional higher frequency source.

Further, using multiple sources, whose data can be separated andidentified using the present method, can have benefits when performingreverse time migration and full waveform inversion.

The at least two sources generate their respective geophysicalwavefields simultaneously. Simultaneous means that the at least twosources produce geophysical wavefields over the same time period. Itdoes not necessarily mean that the at least two sources are triggeredsuch that they produce wavefields at exactly the same time. Forinstance, when dither is used, the wavefields may intentionally begenerated at different times. Of course, when polarity changes are used,the multiple sources may (or may not) produce wavefields at exactly thesame time.

The method may comprise selecting the varying signature such that, oncethe recorded geophysical data is recorded and transformed into anotherdomain, the portion of the recorded geophysical data originating fromthe generated wavefield will be at least partially shifted away from aninterference portion of the recorded seismic data.

The generated propagating geophysical wavefield may be affected byinterfering geophysical energy (e.g. from other geophysical wavefields,possibly produced by another nearby geophysical survey, or backgroundnoise). When this occurs the recorded geophysical data may comprise asignal portion from the generated geophysical wavefield and aninterference portion from the interfering geophysical data. In order toremove the interference portion, the signature pattern should be variedsuch that the at least some of the signal portion will be at leastpartially shifted away from the interference signal in the transformeddomain.

Conventional geophysical interference reduction techniques are noteffective when the geophysical interference is propagating from thebroadside of the line of the receivers. The present method can handlethese interferences well.

The operator may choose the pattern on the basis of prior knowledge orestimations of the geophysical interference. In the case where theinterference is from a neighbouring survey, the operator may choose thepattern on the basis of the known signal coming from the neighbouringsurvey so as to shift the signal portion from the interfering portion.

The pattern may be chosen so that the signal portion is shifted as farfrom the interference portion as possible.

The method may further comprise removing the interference portion.

The interference portion may have a dominant frequency, and the methodmay comprise using a time dither of approximately the same as, a half ofor a quarter of the period of the dominant frequency. This time dithermay be on every second generated wavefield.

The method may comprise selecting the varying signature such that, oncethe geophysical data is recorded and transformed into another domain, aresidual shot noise portion of the recorded geophysical data will be atleast partially shifted away from the portion of the geophysical dataoriginating from the generated geophysical wavefield.

The generated propagating geophysical wavefield may be affected byresidual shot noise. When this occurs, the recorded geophysical data maycomprise a signal portion from the generated geophysical wavefield and aresidual shot noise portion from the residual shot noise.

Residual shot noise occurs in geophysical traces due to each tracecovering a finite time period. A trace typically starts when thegeophysical wavefield is produced and will end when (or before) the nextgeophysical wavefield is produced. However, when the next trace isrecorded, there may be some residual shot noise (e.g. from deepreflections) from previous geophysical wavefields that are recorded.Whilst this is undesirable, it is difficult to avoid. One prior artmethod of avoiding residual shot noise is to lengthen the time of eachtrace. However, this in turn increases the time between subsequentgenerated wavefields, which is inefficient.

In some applications, the “residual shot noise” may actually be part ofthe useful/wanted signal. Such an application is discussed below, whereeffectively the rate at which shots and traces are triggered isincreased such that the time between generating subsequent shots may beless than the time taken for the geophysical wavefield energy signalassociated with each generated geophysical wavefield to be completelyrecorded by the receiver.

Using the present method, the residual shot noise can be shifted awayfrom the desired signal from the source in the appropriate domain suchthat the residual shot noise can be identified. The residual shot noisemay be removed/muted, or separated and used as geophysical data.

Thus, using the present method, there is less of a need to wait forresidual shot noise to die down before taking a subsequent trace. Thus,the time interval between subsequent generated geophysical wavefields(and hence traces) can be reduced, which can increase the density of thedata (e.g. spacing between locations where geophysical wavefields aregenerated by the at least one source), or can increase the speed atwhich the data is taken (e.g. increase the tow speed of the source).This increases the efficiency of geophysical data gathering.

The residual shot noise portion may have a dominant frequency.

The method may comprise using a time dither of approximately the sameas, a half of or a quarter of the period of the dominant frequency ofthe residual shot noise. This time dither may be on every secondgenerated wavefield.

As mentioned above, the periodic pattern of the varying polarity ofsequentially generated geophysical wavefields may be: a second generatedgeophysical wavefield having the same polarity as a first generatedgeophysical wavefield, a third generated geophysical wavefield havingopposite polarity to the second generated geophysical wavefield, afourth generated geophysical wavefield having the same polarity as thethird generated geophysical wavefield, a fifth generated geophysicalwavefield having opposite polarity to the fourth generated geophysicalwavefield, a sixth generated geophysical wavefield having the samepolarity as the fifth generated geophysical wavefield, (i.e. +1, +1, −1,−1, +1, +1, −1, −1), etc.

This pattern may be particularly advantageous for identifying (and henceremoving) residual shot noise. In a trace, the largest residual shotnoise typically comes from the generated wavefield of the previoustrace. This is therefore the most important residual shot noise to dealwith. Using the above pattern allows for this residual shot noise to beidentified as follows:

Say the first generated wave has polarity +1, the second has polarity+1, the third has polarity −1 and the fourth has polarity −1 (etc.). Themain signal in the first trace will have polarity +1, the main signal inthe second trace will have polarity +1, the main signal in the thirdtrace will have polarity −1, and the main signal in the fourth tracewill have polarity −1. However, the largest component of residual shotnoise in a given trace (i.e. that from the previous shot) will have thesame polarity as the main signal in the previous trace. So the largestcomponent of residual shot noise in the first trace will have polarity−1 (same polarity as main component of preceding trace) the largestcomponent of residual shot noise in the second trace will have polarity+1 (same polarity as main component of first trace), the largestcomponent of residual shot noise in the third trace will have polarity+1 (same polarity as main component of second trace) and the largestcomponent of residual shot noise in the fourth trace will have polarity−1 (same polarity as main component of third trace).

We therefore have a set of traces,

t_(n)(main signal polarity, residual shot noise polarity), as follows:t₁(+1, −1), t₂ (+1, +1), t₃ (−1, +1), t₄(−1, −1), etc.

The method may comprise, prior to transforming the data, multiplying alltraces having “+1” polarity as their main signal (i.e. the traces thatare generated by a source with +1 polarity with, in this case t₁ and t₂)by −1. This leaves the set of traces with polarity as follows: t₁(−1,+1), t₂(−1, −1), t₃(−1, +1), t₄(−1, −1), etc.

Alternatively (and completely equivalently, given the terms +1 and −1are merely depicting opposite polarities), the method may comprise,prior to transforming the data, multiplying all traces having “−1”polarity as their main signal (i.e. the traces that are generated by asource with −1 polarity with, in this case t₃ and t₄) by −1. This leavesthe set of traces with polarity as follows: t₁(+1, −1), t₂(+1, +1),t₃(+1, −1), t₄(+1, +1), etc.

Regardless of which of these methods is carried out (they areessentially equivalent), the result is that all the main signals in theset of traces have the same polarity and the residual shot noise hasalternating polarity. Thus, equation 6 above applies to the residualshot noise component only, and not the main signal component.

Thus, when an appropriate transform of the set of traces is taken, theresidual shot noise may be shifted relative to the main signal. In thespecific case given here, the shift is the Nyquist frequency k_(N).

In this application of the present method, it is preferable to have theat least one source generate the wavefields at regular, constant timeintervals, e.g. rather than at regular spacing intervals. (Of course, iftime dither is used, then the regular time intervals may not be totallyconstant, but the average time between shots will be constant, and the“expected” shot trigger time (from which time dither is measured) willbe constant.)

The method may comprise selecting the varying signature such that, oncethe geophysical data is recorded and transformed into another domain, apressure wave portion of the geophysical data will be at least partiallyshifted away from a shear wave portion of the geophysical data.

After reflection from a subsurface structure, the propagatinggeophysical wavefield may comprise reflected pressure waves andreflected shear waves such that the recorded geophysical data comprisesa pressure wave portion and a shear wave portion. However, the shearwaves travel more slowly than pressure waves.

A trace typically starts when the geophysical wavefield is produced andwill end when (or before) the next geophysical wavefield is produced. Itis desirable to record both the shear and the pressure waves. Before thepresent method, if it were desired to record both the shear wave and thepressure wave, it would be necessary to do so in the same trace. This,however, when viewed from the pressure wave alone is not efficientbecause of the delay in the shear wave arrival. Thus, similar to theresidual shot noise discussed above, one prior art method is simply tohave increased of trace times, and increased intervals between generatedgeophysical wavefields. This is inefficient.

Using the present method, the pressure wave and the shear wave mayarrive in different traces. Due to the varying periodic signature of thesource, it will be possible to separate the pressure and shear arrivalsin the transformed domain. Further, due to the varying periodicsignature of the source it will be possible to know from which generatedgeophysical wavefield the shear wave originated, regardless of whichtrace it is recorded in.

The separated shear and pressure waves may both be used as geophysicaldata for analysing the subsea structure. Alternatively, the shear orpressure wave may be removed/muted.

Thus, using the present method, there is less of a need to wait forshear waves to arrive before taking a subsequent trace. Thus, the timeinterval between subsequent generated geophysical wavefields (and hencetraces) can be reduced, which can increase the density of the data (e.g.spacing between locations where geophysical wavefields are generated bythe at least one source), or can increase the speed at which the data istaken (e.g. increase the tow speed of the source). This increases theefficiency of geophysical data gathering. Additionally, in the case ofpressure and shear data acquisition signal-to-noise can also beincreased due to the fact that shear data tend to be mostly arriving onthe horizontal component in seabed recordings and pressure waves mostlyarrive on the vertical component. Thus, after separation of thehorizontal and vertical components, the pressure data and the shear datamay be substantially separated.

The method may comprise generating subsequent geophysical wavefields ata rate that is faster than is conventionally possible. The time betweengenerating subsequent geophysical wavefields may be less than the timetaken for the geophysical wavefield energy signal associated with eachgenerated geophysical wavefield to be completely recorded by thereceiver.

In conventional systems, traces are typically triggered with each shot.Each trace therefore records the wavefield signal generated from eachshot. The wavefield signal takes a certain amount of time to completelybe recorded by the receiver (by “completely” recorded here, we are notreferring to residual noise, we are referring to only the wanted/usefulsignal from the generated wavefield).

However, as mentioned in relation to the residual shot noiseapplication, the traces must be of a certain length so as to record allof the wanted/useful propagating wavefield signal from the respectiveshot, and to avoid too much interference/noise from previous shots.Since the trace and the shot are triggered together, the minimum tracelength leads to a minimum time between shots, and so limits the rate atwhich data can be acquired.

However, in the present invention, it is possible to fire shots and torecord traces at a greater rate. If the signature of the source isvaried in a suitable periodic pattern, any given trace can record thesignal (i.e. the wanted/useful data signal) portion from more than onesource, since the data recorded from each source in each trace can laterbe identified/isolated using the present method. This allows dataacquisition to be much faster.

Once the data in a given trace originating from a source shot previouslyto the trigger time of the given trace has been identified/isolated,this data can be added to the data recorded for the previous shot (i.e.this data can be concatenated with the previous data since this portionof the data has a zero time that corresponds to the trigger of the givenshot). The previous shot may preferably be the shot for the traceimmediately preceding the given trace.

For instance, take the case where the signal from a generated wavefieldtakes time t₀ to fully pass the receiver. Using conventional techniques,the system would be limited to a shot trigger and trace trigger timeinterval of t₀. However, using the present method it is possible tosimultaneously record the signal portion from two subsequent shots inthe same trace, and then separate the recorded data from each shot. Inthis case, shots and traces can be triggered at intervals of

$\frac{t_{0}}{2}.$Further, in the case where it is possible to simultaneously record (inthe same trace) and then separate the recorded data for n subsequentshots, shots and traces can be triggered at intervals of

$\frac{t_{0}}{n}.$

The geophysical wavefield, energy and/or data may be a seismicwavefield, energy and/or data. The geophysical wavefield, energy and/ordata may be a controlled source electromagnetic wavefield, energy and/ordata.

It should be recognised that this application uses the same principalsto those of the residual shot noise application, but that what wasconsidered as “noise” now is “useful” signal that needs to be moved toits right place (i.e. following the end of the previously recordedshot). In other words we deliberately let more of the desired signal endup as “residual shot noise” in the next shot(s) where it can beisolated, removed from the next shot(s) and added to the appropriateprevious shot(s).

The transform may be a Fourier, tau-p or radon transform. Theappropriate domain may be a frequency-wavenumber domain, or a tau-pdomain.

As discussed above, the method may be used to improve the estimation ofsource-side gradients. When conducting data acquisition the source maybe in the form of an array of sub-arrays of sources. The sub-arrays maybe separated vertically and/or horizontally.

Using the present method, data from two or more sources (or sub-arraysof sources) in the array can be found. By knowing the data from eachsource (or sub-array), the calculation of the source-side (horizontaland/or vertical) gradient is greatly eased.

The method may comprise calculating the (horizontal and/or vertical)gradient of the source between two or more sources, or two or moresub-arrays.

Similarly, since the data from a specific source can be identified inthe recorded data using the present method, the calculation forsource-side deghosting of the data is greatly eased, particularly whendata is acquired from multiple sources simultaneously.

The method may comprise source-side deghosting the recorded geophysicaldata.

The separated data produced by the present method may be used toreconstruct or interpolate the geophysical data on the source-side.

The at least one source may be an airgun source, an airgun source array,a marine vibroseis source, a watergun source, a flip/flop source, or anelectric and/or magnetic source. An electric and/or magnetic source maybe an electromagnetic source, i.e. a source for producingelectromagnetic data. Alternatively or additionally, a flip/flop/flapsource (which may comprise three source arrays) or a penta-source (whichmay comprise five source arrays) may be used. A flip/flop source, aflip/flop/flap source and a penta-source are examples of multi-arraysthat can be used as the source of for the present method. Suchmulti-arrays may be towed behind a single vessel.

When a flip/flop source is used with time dither between the flip andflop shots (e.g. either all the flip shots or all the flop shots aredithered by a constant time), the two flip and flop sources may bestaggered in the inline direction to compensate for differences inshooting times. The flip/flop sources may be being moved during shotfiring at a constant velocity. The stagger may be such that the flip andflop shots are spaced equally in space, but are dithered in time. Forinstance, if the flop shot time dither is 0.2 s and the speed of thesource is 2.5 m/s, the flop shot may be 0.5 m in front of the flop shot.The flip/flop source may comprise airgun sources. In this case, theflip/flop source could be considered to be one source, and should not beconfused with the case of using multiple simultaneous sources. (However,a flip/flop source could also be used as two simultaneous sources, ifthey are staggered appropriately in the in line direction.)

Staggering such as this may also be used for any type of source (i.e.not just flip-flop sources) when multiple sources are present.

Such a staggering of sources may be particularly important for anyapplication where the source is triggered at regular, constant timeintervals, e.g. rather than at regular spacing intervals. (Of course, iftime dither is used, then the regular time intervals may not be totallyconstant, but the average time between shots will be constant, and the“expected” shot trigger time (from which time dither is measured) willbe constant.) This may be particularly relevant for the residual shotnoise application discussed above. Staggering the sources in such amanner when using constant time triggering allows for the shot locationsto have constant spatial separation.

The recorded geophysical data may be gathered/sorted in the commonreceiver domain. The recorded geophysical data may be gathered/sorted inthe common midpoint planes domain. The recorded geophysical data may begathered/sorted in the common offset domain. The transform may becarried out on data in either of these domains.

The geophysical data may be 2D data or 3D data.

For 2D data, the recorded data (which may be in the space-time domain)may be recorded in one space dimension (e.g. inline or crossline) andone time dimension. Thus, only one spatial coordinate may be requiredfor 2D data. When transforming into the other domain, the other domainmay also be a two dimensional domain. For instance, when transforminginto the frequency-wavenumber domain, there may only be one wavenumberdimension and one frequency dimension. When using a filter, the filtermay be a 2D filter, and may filter in only one spatial dimension.

For 3D data, the recorded data (which may be in the space-time domain)may be recorded in two space dimension (e.g. inline and crossline) andone time dimension. Thus, two spatial coordinates may be required for 2Ddata. When transforming into the other domain, the other domain may alsobe a three dimensional domain. For instance, when transforming into thefrequency-wavenumber domain, there may be two wavenumber dimensions(e.g. k_(x) and k_(y)) and one frequency dimension (e.g. an (f, k_(x),k_(y)) space). When using 3D data, the shifting can be performed in morethan one dimension (e.g. k_(x) and/or k_(y)). This allows for moresignature options, more shifting options and more space into which toshift the recorded data. When using a filter, the filter may be a 3Dfilter, and may filter in only two spatial dimensions.

The geophysical data may be marine seismic data, seabed seismic data,permanent reservoir monitoring data, land seismic data, VSP data,controlled source electromagnetic data, electric data and/or magneticdata.

When signals from multiple simultaneous sources are separated bytransforming into an appropriate domain, it is preferable that thesignal band is as narrow as possible in that domain. This is so thatoverlap of the signal bands from the different sources is avoid orminimised. For instance, data from each source can be in the form of asignal cone. The data from the different sources may be aliased if thesignal cones overlap. When the signals overlap, it can be difficult toseparate the signals from the different sources. It is therefore animportant consideration to make the widths of the data signals in thetransformed domain as narrow as possible. The inventors have foundseveral ways of doing this, and these are discussed below.

Thus, the method may comprise reducing the width of the data signaloriginating from the at least one source in the other domain. The methodmay comprise reducing the interference of the recorded data originatingfrom multiple sources. This may be achieved by applying data processingand de-aliasing techniques to the data in the first domain, as isdiscussed below or any general data processing technique for thispurpose, for instance as those described in Yilmaz (2001). By signalwidth we mean, for instance, the spatial aperture of the signal cone infk.

The method may comprise reducing the highest apparent wavenumbers. Thismay be done for the data for one or more of the sources. This may bedone prior to transforming, and may be done mathematically (e.g. usingsignal processing), or may be done physically (e.g. by altering thesource-receiver set up). Details on these techniques are given below.

The method may comprise gathering the data in, or sorting the gatherdata into, a domain that minimises the signal width in the transformeddomain. Such a domain may be the common receiver domain, common sourcedomain, common midpoint domain or common offset domain. The commonoffset domain may be preferred because it comprises larger apparentvelocities of arrivals than the common receiver domain, and so thesignal cone will be larger in the frequency-wavenumber domain.

The method may comprise removing low-speed waves of the recordedwavefield, for instance the direct wave arrival, the guided water layerwave arrival and/or the bottom refraction wave arrival. These slow speedwaves are the limiting factor for the signal cone in thefrequency-wavenumber domain, and removing them reduces the width of thesignal cone. These arrivals may be removed by modeling these arrivals,and subtracting them from the recorded data.

The method may comprise having the source and the receiver far apart(such as at least 100 m, 200 m, 500 m, 1000 m, or 10000 m). If data arerecorded far from the source, due to the reduced azimuth range betweensource and receiver, the width of the signal cone will be narrower.

Any of these methods may be performed in combination with each other.

Due to the cone-shape of the signal in the transformed domain, the lowerfrequency data will typically not overlap with low frequency data fromother sources. This lower frequency data may be considered as unaliaseddata. The threshold frequency up to which there is no data overlap andabove which there is overlap will depend on the width of the signalcones and the separation of the signal cones. The higher frequency dataabove the threshold may be considered to be aliased data.

In order to produce non-aliased data from each source, the inventorshave found the following techniques.

The method may comprise reconstructing unaliased data for one or moresources based on the unaliased lower frequency data. There are knowntechniques for achieving this. This method may be performed incombination with any of the wavenumber-limiting techniques discussedabove.

In broadband modeling/acquisition, the lower frequency unaliased datamay predominantly be from the low frequency source(s). Thus, broadbandmodeling/acquisition data may be particularly easily separated using thepresent method.

When using multiple simultaneous sources, all of the sources may be of alow enough frequency such that they do not interfere. Preferably howeverthere may also be one higher frequency source. Because there is only onehigher frequency source, its high frequencies will not interfere withany other signals (and its low frequency signals will not interfere withthe other low frequency sources because of the cone-shape of the data).

Thus, the frequencies of the multiple sources may be selected tominimise interference/aliasing of the data from each source.

It should be appreciated that the method steps discussed above can applyequally to modelling and to physical data acquisition.

The method may comprise applying source motion corrections to therecorded data. This may be performed using any known technique.

The method may comprise regularising the data. This may occur aftertransforming the isolated data back into the original domain (e.g. thetime-space domain), after filtering or after conditioning. The data mayneed to be regularised if the spatial locations at which the wavefieldswere generated by the source are not the desired locations. This may bethe case if the wavefields were triggered with respect to constant timeintervals rather than with respect to constant spacing intervals, or ifa large time dither was used. The regularising may be spatiallyregularising. Regularising the data can be achieved using standardregularising techniques. Regularising can occur in the domain in whichthe data was recorded or in the transformed domain.

It should be noted that all “shifts” in the data discussed above aremerely relative shifts in the transformed domain, i.e. when it is statedthat a first data set is shifted away from a second, it could equally bethought of as shifting the second data set away from the first, orindeed both data sets being shifted relative to another point. The datain the domain may be periodic, e.g. in the frequency-wavenumber domainthe data may have a period of 2k_(N) (i.e. data at k and k+2nk_(N) maybe identical). Thus, it should be understood that the axes may bealtered by effectively shifting all the data. Which data set(s) is/arebeing “shifted” will simply depend on whether the axes in the domain arealso shifted, which can be freely chosen by the operator.

Further, it should be noted that the “shifted location” is not onespecific location/coordinate in the domain, but rather refers to a shiftby the same amount in the domain (e.g. data that would have had acoordinate k₁ when shifted to the “shifted location” has locationk₁+k_(shift) and data that would have had a coordinate k₂ when shiftedto the “shifted location” has location k₂+k_(shift)).

In a second aspect, the invention provides a system for generatinggeophysical data comprising at least one source for generating ageophysical wavefield with a varying signature, wherein the source isconfigured to vary the signature of the geophysical wavefield in aperiodic pattern.

The system may further comprise: at least one receiver for recordinggeophysical energy, the geophysical energy comprising the propagatinggeophysical wavefield generated at the at least one source; and aprocessor for transforming the recorded geophysical data into anotherdomain. The other domain may be a domain such that at least some of therecorded geophysical data is shifted to a location that is different tothe location in the other domain where the at least some of thegeophysical data would have been had the varying signature not beenused. Here, the at least some of the recorded geophysical data may beall or part of the geophysical data originating from the propagatinggeophysical wavefield generated by the source.

The system may comprise at least one receiver for recording geophysicalenergy, the geophysical energy comprising the propagating geophysicalwavefield generated at the at least one source; and a processor forisolating the geophysical data originating from the propagatinggeophysical wavefield generated at the at least one source from anyother geophysical data that may be present in the other domain. Theprocessor comprises a filter for filtering the recorded data. The filtermay be the filter discussed above in relation to the method.

The system may further comprise at least two sources each for generatinga geophysical wavefield, the first source having no varying signatureand the second source having the varying signature, such that thegeophysical data from the second source will be shifted away from thegeophysical data of the first source. Alternatively, each source couldhave a different varying signature, such that the geophysical data fromthe second source will be shifted away from the geophysical data of thefirst source.

The system may be configured to perform any of the above-discussedmethods. The system may comprise any of the features discussed inrelation to the above-discussed methods.

In a third aspect, the invention provides a computer program productcomprising computer readable instructions that, when run on a computer,is configured to: cause at least one source to generate a geophysicalwavefield with a varying signature, wherein the signature is varied in aperiodic pattern.

The computer program product may be configured to perform any of themethods of the first and/or second aspects. The computer program productmay be configured to cause any of the systems of the first and/or secondaspects to perform any of the above discussed methods.

In a fourth aspect, the invention provides a method of prospecting forhydrocarbons. This method comprises performing any of the methods of thefirst and/or second aspects, possibly using the computer program productof the third or seventh aspects. This method may comprise using thesystem of the second aspect and/or the computer program product of thethird aspect to prospect for hydrocarbons.

The method may comprise using the generated geophysical data to identifylocations for drilling and/or identifying well locations using themodel. The method may comprise drilling at and/or into said identifiedlocations.

In a fifth aspect, the invention the invention provides a method ofproducing hydrocarbons. The method may comprise performing any of themethods of the first and/or fourth aspects, and producing hydrocarbonsthrough the drilled wells. This method may comprise using the system ofthe second aspect and/or the computer program product of the thirdaspect to produce hydrocarbons.

BRIEF DESCRIPTION OF THE DRAWINGS

Preferred embodiments of the invention will now be discussed, by way ofexample only, with reference to the accompanying drawings, in which:

FIG. 1 shows an illustration of what a common receiver gather seismicdata set may look like in fk after conventional shooting (left) andflipping polarity on every second shot (right).

FIG. 2 shows an illustration of what a common receiver gather seismicdata set may look like in fk after using a time dither on every secondshot.

FIG. 3 shows an example acquired data set used to illustrate anembodiment of the present invention.

FIG. 4 shows the fk spectrum of the data shown in FIG. 3.

FIG. 5 shows the fk spectrum of the data shown in FIG. 3, but where thepolarity of every second trace has been flipped, emulating a surveywhere every second shot has opposite polarity to the shots right beforeand after.

FIG. 6 shows the fk spectrum of the data shown in FIG. 3 but flippingpolarity on traces such in the pattern +1, +1, −1, −1, +1, +1, −1, −1,etc., emulating a survey where the polarity of shots are flipped in thatpattern.

FIG. 7 shows the fk spectrum of the data shown in FIG. 3 but where atime shift of 10 ms has been applied to every second trace, emulating asurvey where a time dither of 10 ms on every second shot is used.

FIG. 8 shows the fk spectrum of the data shown in FIG. 3 but where atime shift of 20 ms has been applied to every second trace, emulating asurvey where a time dither of 20 ms on every second shot is used.

FIG. 9 shows the fk spectrum of the data shown in FIG. 3 but where atime shift of 40 ms has been applied to every second trace, emulating asurvey where a time dither of 40 ms on every second shot is used.

FIG. 10 shows the fk spectrum of the data shown in FIG. 3 but where atime shift of 200 ms has been applied to every second trace, emulating asurvey where a time dither of 200 ms on every second shot is used.

FIG. 11 shows the data of FIG. 7 where equation 17 has been used toproperly “deghost” the signal cone centred around the Nyquist wavenumberso that the shifted data now again corresponds to the original data (butshifted to the Nyquist wavenumber).

FIG. 12 shows the data shown in FIG. 11 where equation 17 has been usedto properly “reghost” the signal cone centred around the Nyquistwavenumber and subtract it from the signal cone centred around k=0. Weare left with a data set with one signal cone only that has been shiftedto the Nyquist wavenumber.

FIG. 13 shows a possible configuration for a flip/flop source to achievea spatially fully uniform distribution of shot points when time ditheris used.

FIG. 14 shows the effect on signal and residual shot noise arrivalsafter backing off time shifts.

DETAILED DESCRIPTION

In one embodiment, the present method relates to a new way to acquireseismic data based on how seismic sources are utilized. The keyrealization is that by varying the source signature from shot to shot itis possible to separate data from other signals or noise. In oneembodiment of the invention a source boat shoots every second shot witha certain source signature while every intermediate shot is fired withthe same source signature but with opposite polarity. After afrequency-wavenumber (fk) transform of such data, for instance sortedinto a common receiver gather, the data will populate opposite ends ofthe k axis in the fk spectrum compared to where a conventionally shotdata set with the same source signature for every shot would end up. Thetheory of this is discussed in detail below. We can exploit this effectfor a number of different applications, which are each discussed ingreater below:

-   -   1. Simultaneous source acquisition.        -   The technique described here offers a new way to acquire            simultaneous source data. Two or more sources can be fired            simultaneously, and the data received from them can be            separated, through the use of different varying signature            patterns.    -   2. Seismic interference cancellation.        -   By using the present method we can adapt the recorded data            signal so as to shift the data originating from the one or            more sources from seismic interference. To achieve this, the            optimal signature pattern can be adapted as the measurements            are taken.    -   3. Residual shot noise attenuation.        -   By choosing the signature variation pattern appropriately,            we can use the methodology to isolate residual shot noise            that can be removed without affecting the signal at all.            Benefits include better signal-to-noise ratio in the            acquired data, faster acquisition of seismic data, denser            acquisition of seismic data, better low frequency            acquisition (low frequencies tend to be most affected by            residual shot noise).    -   4. Seismic data modelling and reverse time migration (RTM).        -   Since the method allows multiple sources to be used            simultaneously, there can be dramatic efficiency savings            when modelling. For instance, if two sources are used, there            are immediate efficiency savings are up to a factor of 2.    -   5. Broad-band seismic acquisition.        -   As is discussed further below, once shifted, there may be            some aliasing of the data from multiple sources. However,            data from multiple sources are always unaliased for low            frequencies using our method. We can use purpose built low            frequency sources and guarantee that these will not            interfere with the acquisition of conventional data.    -   6. Cost-effective acquisition of shear-wave data.        -   Similarly to the RSN application, by choosing the signature            variation pattern appropriately, we can use the methodology            to isolate the shear-wave arrival from the pressure-wave            arrival.    -   7. Deghosting and source-side gradients for interpolation.        -   By applying the varying source signature pattern to            different sub-arrays within an airgun array, it is possible            to separate the responses from sub-arrays such that            horizontal gradients on the source side can be computed.            These are useful for source-side deghosting and other            applications.            Theory

In the following discussion of the theory behind the present method,techniques that exploit the fact that the fk space in marine seismicdata contains significant portions that are empty limited by apparentpropagation velocities that cannot be lower than the propagationvelocity in water are discussed. However, other domains and geophysicaldata types may also be used.

The left part of FIG. 1 illustrates a frequency-wavenumber (fk) plot of,for instance, a common shot gather or common-receiver gather from amarine seismic survey. All signal energy sits inside a “signal cone”.This is because the slowest possible apparent velocity of any seismicenergy will correspond to the propagation velocity of water. Outsidethis signal cone the data is zero in the fk plot.

The inventors have found that by varying the source signature form shotto shot thereby introducing different shooting patterns it is possibleto make much better use of the available fk space. The data may bedeliberately aliased.

One example of such a shooting pattern is to shoot all even shot pointswith a certain source signature and interleave all odd shot points usingthe same source signature but with opposite polarity. For such a dataset, a recorded common receiver gather will have every second trace withflipped polarity, or in other words, the following modulating functionhas been applied to a conventional data set where all traces had thesame source signature:g ₁(n)=(−1)^(n).  (12)

Equation 12 can also be written asg ₁(n)=e ^(1πn).  (13)

By applying the function g₁ in equation 13 as a modulating function toconventionally recorded (i.e. data recorded without using a varyingsource signature) data f(n), where n is trace number, before taking a(normalized) discrete Fourier transform:

F(f(n))=F(e ^(ik)),

we obtain

(f(n)g ₁(n))=

(f(n)e ^(iπn))=F(e ^(i(k−π))),  (14)

which is a standard Fourier transform result (wavenumber shift). Thatis, modulating a function with equation 12 results in a wavenumber shiftby the Nyquist wavenumber.

The right part of FIG. 1 shows what such a data set would look likeafter an fk transform. Note that the signal cone has now been shiftedlaterally so that it is centred at the Nyquist wavenumber k_(N) withhalf the signal cone on the negative side of the wavenumber axis and theother half on the positive side.

Next we consider the case that we refer to as time dither. In such acase, every second trace may have a time dither T compared toneighbouring traces. The modulating function that we wish to apply canbe written as a superposition of several functions with knowntransforms:

$\begin{matrix}{{g_{2}(n\;)} = {{\frac{1}{2}\left( {- 1} \right)^{n}} + \frac{1}{2} - {\frac{1}{2}\left( {- 1} \right)^{n}e^{i\;\omega\; T}} + {\frac{1}{2}{e^{i\;\omega\; T}.}}}} & (15)\end{matrix}$

Note that the exponentials are due to Fourier transforms in a differentdimension (Fourier transforms of a time shift T) and are constants inthe (space) dimension that we consider.

Equation 15 can be written more compact as, the sum of two modulatingfunctions (one of which is a constant with respect to trace number n):

$\begin{matrix}{{g_{2}(n\;)} = {{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack} + {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}{\left( {- 1} \right)^{n}.}}}} & (16)\end{matrix}$

Finally, we can obtain the result:

$\begin{matrix}{{\mathcal{F}\left( {{f(n)}{g_{2}(n)}} \right)} = {{{\frac{1}{2}\left\lbrack {1 + e^{i\;\omega\; T}} \right\rbrack}{F\left( e^{i\; k} \right)}} + {{\frac{1}{2}\left\lbrack {1 - e^{i\;\omega\; T}} \right\rbrack}{{F\left( e^{i{({k - \pi})}} \right)}.}}}} & (17)\end{matrix}$

Equation 17 shows that the seismic data will be mapped in two places.Part of the data will remain at the signal cone centred around k=0 (i.e.the part with frequencies around ω=π(2n+1)/T) due to the first term ofequation 17 and part of the data will be mapped to a signal cone centredaround the Nyquist wavenumber k_(N) (i.e. the part with frequenciesaround

$\left. {\omega = \frac{2\;\pi\; n}{T}} \right)$due to the second term in equation 17. FIG. 2 illustrates that, incomparison to conventional data (left part of FIG. 1), the data has beenpartially shifted to k_(N). Specifically, the data in the signal cone 1centred around k=0 has not been shifted, but the data in signal cone 2centred around k=k_(N) has been shifted.

Thus, from equation 12 it is clear that when polarity flips are used,substantially all the data from the source will be shifted. However,from equation 17 it is clear that when using time dither data will onlybe partially shifted.

However, the inventors have realised that if one of the terms ofequation 17 is known from recorded data, then the other term can bepredicted using equation 17. This is a critical observation that makestime dither as useful as flipping polarities.

Since it is not necessary to flip the polarity using time dither as thevarying signature, time dither can be performed using conventionalsources (such as airguns). Flipping polarity, on the other hand, mayrequire the use of more specialist equipment, such as marine vibroseis.

As can be appreciated, the theory behind the present method may bepresented in numerous different ways. Another way of considering theorigins of the effect of varying the source signature from shot to shotis that the recorded data then can be considered to consist of a sum ofindividual datasets, where each data set has one individual/specificsource signature. Say, when the source signature is delayed in everysecond shot, the data can be considered to be the sum of two datasets:one without source delay, and the other with source delay. The full datawill have a sampling frequency of k_(s). The two individual datasetsthen will have sampling frequency k_(s)/2. This property leads to allthe benefits in acquisition, processing, modeling and inversion thathave been described in the invention.

Example in Practice

FIG. 3 shows an example data set from a seismic survey. Although thedata comprise a common shot gather sampled at 6.25 m trace spacing, wewill manipulate the data as if it were a common receiver gather whereevery second trace corresponds to a new source location (unrealisticallydensely sampled at 6.25 m source spacing). Only a small part of the datahas been selected such that for instance all near offsets are missing.This will generate some noise artefacts when transforming the data intothe fk space.

FIG. 4 shows an fk plot of the data in FIG. 3. This is an fk plot ofdata gathered using a conventional shooting pattern (e.g. the left-handside of FIG. 1). In this particular case, most of the data arrive withnegative wavenumber. This is because the source is located in front ofthe spread. We can clearly see the outline of a signal cone bounded bythe minimum observable apparent velocity of arrivals (water velocity).We see how some energy “bleeds” outside the signal cone. This is anartefact caused by the fact that we chose a small section of data. Amore complete data set (such as split spread data set with near and faroffsets) would be better focused within the signal cone. However, thedata shown here are good enough to serve the purpose of illustrating ourconcept.

FIG. 5 shows an fk plot where every second trace has opposite polarityto every second trace (e.g. +1, −1, +1, −1, +1, −1, etc.). As expectedthe signal cone has been shifted along the wavenumber axis to becentered around the Nyquist wave number. This is as shown schematicallyin the right-hand side of FIG. 1.

FIG. 6, shows the fk plot of the same data but the polarity is flippedas follows: +1, +1, −1, −1, +1, +1, −1, −1, etc. It can be seen that thesignal cone has been shifted to be centred around positive and negativehalf of the Nyquist wavenumber.

FIGS. 7, 8, 9 and 10 show fk plots of the data after applying a timeshift to every second trace of 10 ms, 20 ms, 40 ms and 200 msrespectively. For instance, the source may be a flip/flop source. Notehow part of the data shift from being centred around wavenumber k=0 tothe opposite end of the wavenumber axis, i.e., the Nyquist wavenumber. Anotch pattern can be seen (in the following referred to as “ghosts”,although these have nothing to do with a sea surface ghost) where forcertain frequencies all the data is shifted and for certain frequenciesnone of the data is shifted. This notching can be understood by lookingat equation 14. For certain frequencies

$\left( {f = \frac{\left( {{2n} + 1} \right)}{2T}} \right.$where T is the dither) all the data will be shifted, and for othercertain frequencies

$\left( {f = \frac{n}{T}} \right)$none of the data will be shifted.

As discussed above, it is possible to remove these notches, and shiftall the data so that is centred around the Nyquist wavenumber. This isshown in FIGS. 11 and 12 where equation 16 is applied to the data with a10 ms time dither (FIG. 7) to illustrate how we can recover amplitude ofa signal cone that has been shifted to the Nyquist wavenumber (even ifthe signal cone around k=0 is lost or completely masked in noise orother data). This estimate is also used to “reghost” the data (thisterms as used here has nothing to do with the sea surface ghost problem)to fully remove all that is left at k=0.

FIG. 11 shows the data of FIG. 7 where equation 17 has been used toproperly “deghost” the signal cone centred around the Nyquist wavenumberso that the shifted data now again corresponds to the original data (butshifted to the Nyquist wavenumber).

FIG. 12 shows the data shown in FIG. 11 where equation 17 has been usedto properly “reghost” the signal cone centred around the Nyquistwavenumber and subtract it from the signal cone centred around k=0. Weare left with a data set with one signal cone only that has been shiftedto the Nyquist wavenumber.

Thus, using time dither, the data is partially shifted. However, thenon-shifted data can be shifted mathematically by understanding thetheory behind the shifting.

Now some applications of the present method are described, by way ofexample only.

1. Simultaneous Source Acquisition

In one embodiment we have two source boats. The first boat shoots everysecond shot with opposite polarity. The other boat acquires dataconventionally (i.e. with no varying signature). The recorded data, in acommon receiver gather, will contain a superposition of the two datasets. However, after an fk transform, the data separates to oppositeends of the k axis in the fk spectrum (one cone centred at wavenumberk=0 from the conventional source and the other cone centred at +/− theNyquist wavenumber from the varying-signature source). The two data setscan now be isolated and inverse transformed back to the space-timedomain to obtain the data sets corresponding to each source boatseparately. The data set where every second trace has opposite polaritycan now be conditioned so that every trace has the same polarity.

In another embodiment, one source is fired without a time shift whereasa second source is fired using a constant time dither (e.g., 10 ms asshown above) for every second shot. The data from the first source willalways end up in a signal cone around k=0. However, the data from thesecond source will be split between two signal cones; one centred aroundk=0 and one centred around the Nyquist wavenumber in accordance withequation 14. The above theory shows how to:

(1) Fully recover the data from the second source using the signal conearound Nyquist wavenumber only (through what resembles the “deghosting”operation discussed above).

(2) Remove all energy from the second source that was left behind in thesignal cone centred around k=0. In other words, the data from the firstsource is fully recovered.

The concepts of these two embodiments can be generalized to more thantwo sources and to different varying signatures. For instance, by havinga third source with a time dither on two consecutive shots and then notime dither on the next two consecutive shots, then time dithers on thefollowing two consecutive shots, etc., we will obtain data with a newsignal cone introduced, centred around half the Nyquist wavenumber.

Note that even though large parts of the fk space are empty inconventionally acquired data, common receiver gathers typically areacquired sparse so that they alias already at frequencies inside thefrequency band of interest. Using the technique described here, the twodata sets will start to interfere at an even lower frequency becausesignal cones of the data from the various sources may overlap above acertain threshold frequency value. It is desirable to avoid this as muchas possible. The inventors have found several ways to mitigate aliasedand/or interfering data:

a. Instead of separating the data in common receive gathers, data couldbe separated in another domain such as common offset gathers. Commonoffset gathers are largely flat and apparent velocities will be muchhigher compared to common receiver gathers and therefore separate muchbetter after an fk transform, i.e. the signal cone will have steepersides, and hence be narrower, and so will interfere less with othersignal cones. As long as the sequence of modulating time shifts fromtrace to trace is maintained in such a gather, we will separate the dataas desired in fk.

b. Since the lowest frequencies in each signal data cone will notoverlap with other data cones (due to the shape of the data cone), thelowest frequencies are always unaliased. Dealiasing the aliased higherfrequencies can be carried out using known techniques. On such technique“Interpolation with priors” (Spitz, 1991; Ozbek et al., 2009; Vasallo etal., 2010; Ozbek et al., 2010) exploit the fact that (1) a model of anunaliased higher frequency can be predicted from the aliased data, (2)the use of a lower unaliased frequency to compute priors, and (3) anassumption such as that the data contains linear events only in fk. Suchdealiasing will be very effective on the types of data that we proposeto acquire also in cases of using a greater number of source boats thantwo.

c. By removing the direct wave, waves guided in the water layer, waterbottom refractions, etc. (e.g., by modelling), the width of the signalcone can be narrowed substantially so that the signal cones are betterseparated in fk and the method will be more effective.

d. If data are recorded far away from a recording location, the signalcone on a common receiver gather will appear narrower as the azimuthrange is limited. Finding appropriate gathers to sort simultaneoussource data on can be used to ensure that at least one signal cone isnarrower and separated better from the other(s).

These mitigation methods are applicable to any application of thepresent method where multiple sources are used.

2. Seismic Interference Cancellation

Seismic interference is the undesired influence of a different seismicsurvey conducted in the vicinity of the own seismic survey. Seismicinterference (SI) is relatively easy to remove if the interferingseismic energy is arriving in the inline direction of the seismicsurvey. However, a particularly difficult case is seismic interferencearriving from the broad side. Using the technique described in thisreport we can move the signal to be as far as possible in the fkspectrum from the SI.

SI data often has a low frequency bias compared to the seismic dataacquired. In order to remove as much SI as possible, when using timedither a large time shift should preferably be chosen similar to halfthe dominant period in the SI. We expect the SI application to workparticularly well due to the band-limited nature of SI such that one canavoid interference with the data being acquired (low frequencies shiftedaway from the data along the wavenumber axis will fully fall outside thesignal cone of the data acquired).

Using the present method the operator can make sure that the recordeddata set will always be acquired at opposite side of the k axis comparedto the seismic interference after an fk transform independent of thearrival direction of the seismic interference. The interfering data willtherefore be even easier to remove than the currently most benign caseof inline interference. The appropriate signature (e.g. the polarityvariation or deterministic time shift dithering) sequence can be chosendirectly in the field when encountering seismic interference. Forinstance, if the SI is caused by another vessel shooting seismic waves,it may be possible to select the signature appropriately if the sourcetrigger times of the other vessel are known.

3. Residual Shot Noise Attenuation

Residual shot noise (RSN) is recorded energy that arrives from deepreflections, shear wave conversions, high order multiples orcombinations thereof but that were generated from the previous shot. Itis a principal form of shot generated noise that limits signal-to-noisein recorded data in cases where other noise types such as ambient noiseare weaker. Therefore, in such scenarios, if we can reduce RSN we caneither i) shoot seismic data quicker (leading to faster tow speed andtherefore shorter records), ii) shoot more densely, or iii) we canalways guarantee that the data will be of higher quality if we retainthe same towing speed and shot density. The removal of RSN can thereforehave a significant impact on the cost efficiency of a survey. Note thatRSN is particularly problematic for low frequencies since low frequencydata suffer less from attenuation in the Earth's subsurface andtherefore require longer times to decay before we are ready to acquire anew uncontaminated shot.

In one embodiment, the following method may be used to isolate residualshot noise when acquiring seismic data using one source boat. First,shoot two consecutive shots with the same polarity. Then shoot twoconsecutive shots with opposite polarity. Next again shoot twoconsecutive shots with the same polarity as the first two followed bytwo with opposite polarity, etc. After acquiring the data, multiply allshots with opposite polarity with −1 (or multiply all shots withpositive polarity with −1) such that all traces now have the samepolarity. Interestingly, the residual shot noise will have oppositepolarity on every second trace. Because of this, after an fk transform,the residual shot noise ends up on the opposite side of the k axiscompared to the desired signal and can be efficiently muted.

In another embodiment, flip/flop sources may be used so that the timebetween consecutive flop shots is always the essentially same andessentially also the same as the time between consecutive flip shots.However, the time between a flip and a flop shot is different comparedto the time between a flop and a flip shot.

FIG. 13 illustrates how flip/flop data with these types of time shiftscan be acquired with fully uniform shot positions. The top of FIG. 13shows a conventional flip/flop source arrangement where the two starsrepresent the two airgun arrays that have the same inline offset but areshifted in the cross line direction. In the bottom of FIG. 13additionally the flip source has been shifted compared to the flopsource in the inline direction.

As an example, consider a case where data are acquired with a tow speedof 2.5 m/s. In a conventional flip/flop acquisition data is shot every10 s so that we obtain a distance between flop shots of 50 m and adistance between flip shots of 50 m as well. Flip and flop shots areperfectly staggered with respect to each other.

In our method a slight time shift between flip and flop shots may beintroduced as the time dither. For example, the time between flip andflop shots is 9.8 s and the time between flop and flip shots is 10.2 s.By staggering the sources in the inline direction as illustrated in thelower half of FIG. 10, it is possible to still acquire data on a fullyuniform grid. All that we require is to stagger the sources by adistance that corresponds to the distance that the boat moves forwardover 0.2 s which in our case is 0.5 m. Note that for the preferredstaggering times of say 10 ms or 20 ms, this distance is so short thatit can be ignored (2.5 cm in the case of a 10 ms time shift) such thatwe can continue to tow flip/flop sources as is conventionally done (topof FIG. 13).

FIG. 14 illustrates a common receiver gather acquired using flip/flopshooting using a conventional technique (left) and the new methoddescribed here after backing off the time shift that was introducedduring acquisition (right). The case illustrated shows where we tow thesources faster using the new technique such that the record length isshorter on the right hand of FIG. 14 compared to the left. Both signaland shot generated noise (RSN) from flop sources are coloured blackwhereas arrivals due to the flip source are coloured grey. In theconventional case we note that both signal and RSN are coherent andcontinuous from shot to shot. However, using the present method we notethat whereas the signal becomes continuous from shot to shot, RSNsuffers a time shift that is twice that of the original time shiftintroduced during acquisition. That is, if data were shot with 9.8 sbetween flip and flop shots and 10.2 s between flop and flip shots, RSNwill be shifted by 0.4 s from trace to trace after backing of theoriginal time shift such that the signal is continuous between shots.This effect can be exploited to move RSN away from signal centred aroundwavenumber k=0 to the opposite end of the wavenumber axis (Nyquistwavenumber) as described above. We can now fully remove the RSN withoutharming the signal after a suitable transform to the fk domain forinstance. Note that the optimal choice of staggering times between flipand flop sources will depend on geology and the character of the RSN. Itis likely that just as in the case of the SI application, we willbenefit from focussing on low frequencies only (just as for SI, RSNtends to be particularly severe at low frequencies). Again, a particularadvantage of the low-frequency bias is that we will be much less proneto problems with spatial aliasing.

Whilst this has been discussed in terms of flip/flop sources, the sameprinciple may be used for any source with a periodic varying signature.

4. Seismic Data Modelling and Reverse Time Migration (RTM).

Seismic modelling engines such as finite differences (FD) form the basisof state-of-the-art modelling, imaging and inversion algorithms. Suchmodelling engines are extremely computational intensive and if sogenerating synthetic data using more than one shot point at a time couldincrease the efficiency significantly.

It is clear that using the present method one can immediately recoverunaliased synthetic data with two (or more) simultaneous sources usingthe techniques described herein. This is particularly the case if allbut one of the sources only contain low frequencies up to the pointwhere they would start to interfere with the other data, since in thiscase the generated data is always unaliased and can be recovered forsufficiently low frequencies.

Thus, low-frequency data can be acquired at the same time as aconventional source and so—in terms of computing power—are effectivelyacquired for free. The low-frequency data is of low enough frequency sothat that it will not interfere with any of the data from the other lowfrequency source(s) or the conventional source(s).

Further, the above-discussed techniques relating to minimisinginterference and aliasing can be used to mitigate interference andaliasing issues between sources.

5. Broadband Seismic Acquisition

In order to perform broadband acquisition, it has been proposed to use adedicated low frequency source, such as a “sub-woofer” in combinationwith a conventional source (Berkhout (2012)). Using our invention we canacquire such “sub-woofer data” simultaneously with a conventional sourcethat cover a little low frequencies but mostly intermediate and highfrequencies. Acquiring the “sub-woofer data” flipping polarity at everysecond shot point can therefore be done without interfering with theconventional data at all (similarly to the modelling applicationdescribed earlier). Alternatively, time dither could be used.

Depending on the maximum frequency of the “sub-woofer data”, we can alsochoose to acquire it sparser without interfering with the conventionallyshot data or without aliasing the “sub-woofer data” themselves. However,marine vibroseis are known to be inefficient at emitting lowfrequencies. Therefore, even if we have a purpose built low-frequencymarine vibroseis we will likely benefit from shooting often tocompensate for the weaker output.

Thus, the multiple simultaneous sources can comprise at least one lowfrequency source and at least one conventional source.

6. Cost-Effective Acquisition of Shear-Wave Data

Converted wave (shear) data can be acquired much more efficiently usingthe time dither, or polarity flipping, concept enabling record lengthsthat are similar to those of conventional pressure data. The procedureand benefits are analogous to those described under the RSN applicationoutlined above.

Note that both RSN and shear waves occur late in the record and in bothcases the apparent wavenumbers are limited (waves mostly arrive close tothe vertical) such that time dither will work particularly well.

In the case of pressure and shear data acquisition we also benefit fromthe fact that shear data tend to be mostly arriving on the horizontalcomponent in seabed recordings thus leading to more favourablesignal-to-noise ratio in the separation process. Likewise pressure datadominate the pressure and the Z recordings.

Finally, just as in the RSN application, we benefit from the fact thatthe recorded shear arrivals typically lack high frequencies andtherefore are limited to lower apparent wavenumbers, and so are lesslikely to interfere.

7. Deghosting and Source-Side Gradients for Interpolation

By applying the dithering sequences to different sub-arrays within anairgun array, it is possible to separate the responses from sub-arrayssuch that horizontal gradients on the source side can be computed. Theseare useful for source-side deghosting and other applications.

If the simultaneous source concept is used for sources (or sub-arrays)that are closely located to each other, one can estimate spatialderivatives in the vertical and horizontal directions. Note that we canuse different signature sequences to have three (or even moresub-arrays) firing at the same time with different dithers that then canbe separated. From these data spatial derivatives of the wavefield onthe source side can be computed for a range of applications, forinstance for: vertical derivative can be used for source-side deghostingand/or horizontal derivatives can be used for spatial reconstruction ofthe wavefield on the source side (Robertsson et al., 2008).

Essentially, in this case, the array (or sub array) is treated as acomprising multiple sources. If the signature of each source or each subarray is varied in accordance with the present method, it is possible toknow what recorded data came from each source (or sub array). Knowingthis can greatly ease deghosting and source-side gradient calculations.

It should be apparent that the foregoing relates only to the preferredembodiments of the present application and the resultant patent.Numerous changes and modification may be made herein by one of ordinaryskill in the art without departing from the general spirit and scope ofthe invention as defined by the following claims and the equivalentsthereof.

REFERENCES

-   Berkhout, A. J. (2012). Blended acquisition with dispersed source    arrays. Geophysics, 77(4), A19-A23.-   Özbek, A., Özdemir, A. K., & Vassallo, M. (2009, Jan.).    Interpolation by matching pursuit. In 2009 SEG Annual Meeting.    Society of Exploration Geophysicists.-   Özbek, A., Vassallo, M., Özdemir, K., van Manen, D. J., &    Eggenberger, K. (2010). Crossline wavefield reconstruction from    multicomponent streamer data: Part 2—Joint interpolation and 3D    up/down separation by generalized matching pursuit. Geophysics,    75(6), WB69-WB85.-   Robertsson, J. O. A., I. Moore, M. Vassallo, A. K. Özdemir, D. J.    van Manen and A. Özbek, 2008, On the use of multicomponent streamer    recordings for reconstruction of pressure wavefields in the    crossline direction: Geophysics, 73, A45-A49.-   Spitz, S. (1991). Seismic trace interpolation in the FX domain.    Geophysics, 56(6), 785-794.-   Vassallo, M., Özbek, A., Özdemir, K., & Eggenberger, K. (2010).    Crossline wavefield reconstruction from multicomponent streamer    data: Part 1—Multichannel interpolation by matching pursuit (MIMAP)    using pressure and its crossline gradient. Geophysics, 75(6),    WB53-WB67.-   Yilmaz (2001): Seismic Data Analysis: Processing, Inversion, and    Interpretation of Seismic Data, Investigations in Geophysics: SEG

We claim:
 1. A method of generating geophysical data using at least oneairgun source, the method comprising: generating a geophysical wavefieldwith a varying signature using the at least one airgun source, whereinthe signature of the geophysical wavefield is varied in a periodicpattern by using a deterministic variation of a signature of the atleast one airgun source; and using a deterministic variation of thesignature of the at least one airgun source comprises varying at leastone of: the time at which the geophysical wavefield is generated by theat least one airgun source: the polarity of the at least one airgunsource; the phase of the at least one airgun source; and the amplitudeof the at least one airgun source.
 2. A method as claimed in claim 1,further comprising: recording geophysical energy to produce geophysicaldata using at least one receiver, the geophysical energy comprising apropagating geophysical wavefield generated at the at least one source;transforming the geophysical data into another domain, wherein the otherdomain is a domain such that at least some of the geophysical data isshifted to a location that is different to the location in the otherdomain where the at least some of the geophysical data would have beenhad the varying signature not been used; and isolating the geophysicaldata originating from the propagating geophysical wavefield generated atthe at least one source from any other geophysical data that may bepresent in the other domain.
 3. A method as claimed in claim 2, furthercomprising transforming the isolated geophysical data back into thedomain in which the geophysical data was recorded.
 4. A method asclaimed in claim 2, further comprising: conditioning the isolated dataso as to effectively remove the varying signature pattern from therecorded geophysical data and/or regularizing the isolated data.
 5. Amethod as claimed in claim 4, wherein the conditioning step occurs inthe other domain or in the domain in which the geophysical data wasrecorded.
 6. A method as claimed in claim 2, wherein the periodicpattern is such that, after transforming the recorded geophysical datainto another appropriate domain, a first portion of the recordedgeophysical data originating from the propagating geophysical wavefieldgenerated by the at least one source would be shifted relative to asecond portion of the recorded geophysical data originating from thepropagating geophysical wavefield generated by the at least one source,and the method comprises: identifying the first portion; and processingthe data to calculate a full data signal at the shifted location of thefirst portion using the identified first portion and/or to remove thesecond portion of the data using the identified first portion.
 7. Amethod as claimed in claim 1, further comprising: recording geophysicalenergy to produce geophysical data using at least one receiver, thegeophysical energy comprising a propagating geophysical wavefieldgenerated at the at least one source; and isolating the geophysical dataoriginating from the propagating geophysical wavefield generated at theat least one source from any other geophysical data that may be presentin the other domain.
 8. A method as claimed in claim 1, wherein thesignature is varied using time dither and the varying time dither isthat every second geophysical wavefield generated by the at least onesource is triggered with a constant delay of time T.
 9. A method asclaimed in claim 1, wherein the signature is varied by varying apolarity and varying polarity is that every second geophysical wavefieldgenerated by the at least one source has opposite polarity.
 10. A methodas claimed in claim 1, comprising selecting the varying signature of theat least one source such that, once geophysical energy comprising thegenerated geophysical wavefield and another signal is recorded and therecorded geophysical data is transformed into another appropriatedomain, the recorded geophysical data originating from the generatedgeophysical wavefield would be shifted away from recorded geophysicaldata originating from the other signal.
 11. A method as claimed in claim10, wherein the other signal arises from noise, interference, or one ormore other sources.
 12. A method as claimed in claim 1, wherein at leasttwo sources are used to simultaneously generate geophysical wavefields,a first source having a varying signature in a periodic and a secondsource having no varying signature in a periodic, or having a differentvarying signature in a periodic pattern and/or wherein the methodcomprises selecting the varying signature such that, once thegeophysical data is recorded and transformed into another domain, apressure wave portion of the geophysical data will be at least partiallyshifted away from a shear wave portion of the geophysical data.
 13. Amethod as claimed in claim 1, the method comprising selecting thevarying signature such that, once the recorded geophysical data isrecorded and transformed into another domain, a portion of the recordedgeophysical data originating from the generated wavefield would be atleast partially shifted away from an interference portion of therecorded geophysical data.
 14. A method as claimed in claim 13, whereinthe signature is varied using time dither, and wherein a interferenceportion has a dominant frequency, and the method comprises using a timedither of approximately the same as, a half of or a quarter of theperiod of the dominant frequency.
 15. A method as claimed in claim 1,the method comprising selecting the varying signature such that, oncethe geophysical data is recorded and transformed into another domain, aresidual shot noise portion of the recorded geophysical data would be atleast partially shifted away from the portion of the geophysical dataoriginating from the generated geophysical wavefield.
 16. A method asclaimed in claim 15, wherein the signature is varied using time dither,and wherein the residual shot noise portion has a dominant frequency,and the method comprises using a time dither of approximately the sameas, a half of or a quarter of the period of the dominant frequency ofthe residual shot noise.
 17. A method as claimed in claim 15, whereinthe signature is varied by varying a polarity, and wherein the residualshot noise portion has a dominant frequency, and the periodic pattern ofthe varying polarity of sequentially generated geophysical wavefieldsis: a second generated geophysical wavefield having the same polarity asa first generated geophysical wavefield, a third generated geophysicalwavefield having opposite polarity to the second generated geophysicalwavefield, a fourth generated geophysical wavefield having the samepolarity as the third generated geophysical wavefield, a fifth generatedgeophysical wavefield having opposite polarity to the fourth generatedgeophysical wavefield, a sixth generated geophysical wavefield havingthe same polarity as the fifth generated geophysical wavefield, (+1, +1,-1, -1, +1, +1, -1, -1).
 18. A method as claimed in claim 1, wherein atime between generating subsequent geophysical wavefields is less thanthe time taken for the geophysical wavefield energy originating fromeach generated geophysical wavefield to be recorded by a receiver, themethod comprising identifying the data in a given trace originating froma geophysical wavefield generated previously to a trigger time of thegiven trace, and adding this identified data to data on a previous traceoriginating from the same geophysical wavefield.
 19. A method as claimedin claim 1, comprising reducing a width of a data signal originatingfrom the at least one source in an other domain.
 20. A method as claimedin claim 19, when the geophysical wavefield, energy and/or data is aseismic wavefield, energy and/or data, comprising removing low-speedwaves of a recorded wavefield.
 21. A method as claimed in claim 1 usedin a modeling, imaging or inversion method; and/or wherein thegeophysical data is 2D or 3D geophysical data; and/or wherein thegeophysical wavefield, energy and/or data is a seismic wavefield, energyand/or data, or the geophysical wavefield, energy and/or data is acontrolled source electromagnetic wavefield, energy and/or data; and/orwherein a transform may be a Fourier, tau-p or radon transform.
 22. Asystem for generating geophysical data comprising: at least one airgunsource for generating a geophysical wavefield with a varying signature,wherein the at least one airgun source is configured to vary thesignature of the geophysical wavefield in a periodic pattern by using adeterministic variation of a signature of the at least one airgunsource; and using a deterministic variation of the signature of the atleast one airgun source comprises varying at least one of: the time atwhich the geophysical wavefield is generated by the at least one airgunsource: the polarity of the at least one airgun source; the phase of theat least one airgun source; and the amplitude of the at least one airgunsource.
 23. A system as claimed in claim 22, comprising: at least onereceiver for recording geophysical energy, the geophysical energycomprising a propagating geophysical wavefield generated at the at leastone source; and a processor for: transforming the recorded geophysicaldata into another domain, wherein the other domain may be a domain suchthat at least some of the recorded geophysical data is shifted to alocation that is different to the location in the other domain where theat least some of the geophysical data would have been had the varyingsignature not been used; or isolating the geophysical data originatingfrom the propagating geophysical wavefield generated at the at least onesource from any other geophysical data that may be present in the otherdomain and the processor comprises a filter for filtering the recordeddata.
 24. A system as claimed in claim 22, comprising at least twosources each for generating a geophysical wavefield, a first sourcebeing configured to vary the signature of its geophysical wavefield in aperiodic pattern, and a second source being configured not to vary thesignature of its geophysical wavefield in a periodic pattern, orconfigured to vary the signature of its geophysical wavefield in adifferent periodic pattern.
 25. A system as claimed in claim 22configured to generate a geophysical wavefield with a varying signatureusing at least one source, wherein the signature is varied in a periodicpattern.